Exhaust stacks of power plants and other fossil fuel burning machinery contain high levels of both water vapor and CO2. There is much discussion regarding the removal and capture of CO2 from these streams in an effort to abate global warming concerns. However, adsorbent and absorbent materials, which are attracted to CO2, also have a strong or preferential attraction for H2O, thus their use in CO2 capture has thus far not been considered practical.
State of the art systems thus far developed utilize amines (monoethanolamine (MEA), for example) or amino acid salts to absorb the CO2 in an absorption unit and then transfer the amines to a stripper unit where heat, or heat and a reduction in pressure are used to desorb the CO2 into a separate concentrated stream. The concentrated CO2 stream is then available for use or sequestration.
A primary factor in preventing an increased adoption of this technology for sequestration is the energy penalty incurred through the desorption process. NETL report “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminus Coal and Natural Gas to Electricity” Vol. 1, DOE/NETL-2007/1281, (revised November 2010), details capital and operating costs for various types of power plants with and without carbon capture, and is summarized in “Fossil Energy Power Plant Desk Reference (DOE/NETL-2007/1282). Conclusions of the study show power plant efficiency is reduced from 6-12 percentage points with the addition of Carbon Capture and Sequestration (CCS).
The loss in performance is primarily due to the high thermal requirement for stripping the CO2 from the amine solution. For example, in the detailed report noted above, case 13 and 14 of a Natural Gas Combined Cycle (NGCC) plant operates without CCS and produces 555 MW of power with a Net plant efficiency of 50.2% (HHV) (see table 5-7). With CCS, the output is reduced to 473 MW (14% reduction in power) and Net Efficiency reduced to 42.8% (HHV) (See Exhibit 5-18). A portion of the loss in output is due to the physical operation of the secondary amine system, and the added demand of compressing the CO2 (totaling approximately 27 MW of required power to achieve). However, the larger loss is due to the Steam Turbine output reduction as heat is transferred for amine stripping (or regeneration). In the above examples 188 MW of thermal energy is transferred from productive use powering the Low Pressure Turbine to strip the amine solution, resulting in a loss of 54 MW of electrical output.
The required thermal energy for the stripper in this example amounts to 3,716 KJ/KG of CO2 stripped. This is considerably higher than the specific heat of vaporization of CO2, which is just 571 KJ/KG. Theoretically CO2 should be able to be adsorbed and desorbed by a sorbent in a similar fashion to water vapor being adsorbed and desorbed by a desiccant. In the case of desiccant regeneration, energy needs have been demonstrated to require only 125% of the heat of condensation and certainly below 200%. It would then follow that the same should be true for CO2 with an appropriate sorbent, should water vapor not be present to detract from the adsorption/desorption process. Therefore, given the H2O example, it can be concluded that CO2 should be able to be adsorbed for a level close to the heat input in the range of 125% to 200% of 571 KJ/KG heat of condensation, or between 714 and 1141 KJ/KG.
There is a growing market for the use of CO2 sources for Enhanced Oil Recovery (EOR). Currently it is generally accepted that the market is willing to pay $20 a ton for the economical use of CO2 for such purposes. However, the high-energy penalties of the current state of the art process cannot support such a low price, without additional subsidies. Current discussions pick an achievable cost of not lower than $38/ton CO2 with the state-of-the-art amine process. The reduction in heat utilization for desorption disclosed herein could play a key role in helping to reduce production costs of CO2 through sequestration closer to market price for CO2 as a valued commodity.